Directional drilling involves controlling the direction of a borehole as it is being drilled. Since boreholes are drilled in three dimensional space, the direction of a borehole includes both its inclination relative to vertical as well as its azimuth. Usually the goal of directional drilling is to reach a target subterranean destination with the drill string, typically a potential hydrocarbon producing formation.
In order to optimize the drilling operation and wellbore placement, it is often desirable to be provided with information concerning the environmental conditions of the surrounding formation being drilled and information concerning the operational and directional parameters of the drill string including the downhole motor drilling assembly and the drill bit assembly. For instance, it is often necessary to adjust the direction of the borehole frequently while directional drilling, either to accommodate a planned change in direction or to compensate for unintended and unwanted deflection of the borehole. In addition, it is desirable that the information concerning the environmental, directional and operational parameters of the drilling operation be provided to the operator on a real time basis. The ability to obtain real time data measurements while drilling permits a relatively more economical and more efficient drilling operation.
For example, the performance of the downhole motor drilling assembly, and in particular the downhole motor, and the life of the downhole motor may be optimized by the real time transmission of the temperature of the downhole motor bearings or the rotations per minute of the drive shaft of the motor. Similarly, the drilling operation itself may be optimized by the real time transmission of environmental or borehole conditions such as the measurement of natural gamma rays, borehole inclination, borehole pressure, resistivity of the formation and weight on bit. Real time transmission of this information permits real time adjustments in the operating parameters of the downhole motor drilling assembly and real time adjustments to the drilling operation itself.
Accordingly, various systems have been developed that permit downhole sensors to measure real time drilling parameters and to transmit the resulting information or data to the surface substantially instantaneously with the measurements. For instance, mud pulse telemetry systems transmit signals from an associated downhole sensor to the surface through the drilling mud in the drill string. More particularly, pressure, modulated with the sensed information from the downhole sensor, applied to the mud column is received and demodulated at the surface. The downhole sensor may include various sensors such as gamma ray, resistivity, porosity or temperature sensors for measuring formation characteristics or other downhole parameters. In addition, the downhole sensor may include one or more magnetometers, accelerometers or other sensors for measuring the direction or inclination of the borehole, weight-on-bit or other drilling parameters.
Typically, these systems, such as the mud pulse telemetry system, are located above the downhole motor drilling assembly. For instance, when used with a downhole motor, the mud pulse telemetry system is typically located above the motor so that it is spaced a substantial distance from the drilling bit in order to protect or shield the electronic components of the system from the effects of any vibration or centrifugal forces emanating from the drilling bit. Further, the downhole sensors associated with the system are typically placed in a non-magnetic environment by utilizing monel collars in the drill string below the system.
Thus, the telemetry system and the sensors may be located a significant distance from the drilling bit. As a result, the environmental information measured by the system may not necessary correlate with the actual conditions surrounding the drilling bit. Rather, the system is responding to conditions which are substantially spaced from the drilling bit. For instance, a conventional telemetry system may have a depth lag of up to or greater than 60 feet. As a result of this information delay, it is possible to drill out of a hydrocarbon producing formation before detecting the exit, resulting in the need to drill several meters of borehole to get back into the pay zone. The interval drilled outside of the pay zone results in costly lost production over that interval over the life of the well. In some instances this represents millions of dollars in lost production revenue to the operator, not to mention the wasted cost of putting completion equipment over that non-producing interval to reach producing zones further down in the well.
Other difficulties arise with the lag in the sensor to drill bit distance in deciding when it is appropriate to stop drilling and run casing in the borehole. This is often driven by formation characteristics. As well, it is desirable to set a casing section in or before certain formations to avoid further drilling or production problems later on.
In response to this undesirable information delay or depth lag, various near bit sensor systems or packages have been developed which are designed to be placed adjacent or near the drilling bit. The near bit system provides early detection of changes to the formation while drilling, minimizing the need for lengthy corrective drilling intervals and service costs. The drilling operation, including the trajectory of the drilling bit, may then be adjusted in response to the sensed information. However, such near bit sensors continue to be located a spaced distance from the drill bit assembly which still introduces a lag in determining formation changes. In addition, packaging sensors in a mud motor tends to be very costly and may reduce the reliability of the system because the cross section of the motor must now share mechanical power transmission and fluid flow to the bit with space for sensors and supporting electronics.
Further, in order to use a near bit sensor system and permit real time monitoring and adjustment of drilling parameters, a system or method must be provided for transmitting the measured data or sensed information from the downhole sensor either directly to the surface or to a further telemetry system, typically a long haul system, for subsequent transmission to the surface. Similarly, a system or method may need to be provided for transmitting the required electrical power to the downhole sensor system from the surface or some other power source. Various attempts have been made in the prior art to transmit information and/or power directly or indirectly between a downhole location and the surface. However, none of these attempts have provided a fully satisfactory solution.
For instance, various systems have been developed for communicating or transmitting the information directly to the surface through an electrical line, wireline or cable to the surface. These hard-wire connectors provide a hard-wire connection from near the drilling bit to the surface, which has a number of advantages. For instance, these connections typically permit data transmission at a relatively high rate and permit two-way or bidirectional communication. However, these systems also have several disadvantages.
First, a wireline or cable must be installed in or otherwise attached or connected to the drill string. This wireline or cable is subject to wear and tear during use and thus, may be prone to damage or even destruction during normal drilling operations. The drilling assembly may not be particularly suited to accommodate such wirelines, with the result that the wireline sensors may not be able to be located in close proximity to the drilling bit. Further, the wireline may be exposed to excessive stresses at the point of connection between the sections of drill pipe comprising the drill string. As a result, the system may be somewhat unreliable and prone to failure. In addition, the presence of the wireline or cable may require a change in the usual drilling equipment and operational procedures. The drilling assembly may need to be particularly designed to accommodate the wireline. As well, the wireline may need to be withdrawn and replaced each time a joint of pipe is added to the drill string. Finally, there may be a need for through-bore access through the drill string for particular equipment or operations.
Systems have also been developed for the transmission of acoustic or seismic signals or waves through the drill string or surrounding formation. The acoustic or seismic signals are generated by a downhole acoustic or seismic generator. However, a relatively large amount of power is typically required downhole in order to generate a sufficient signal such that it is detectable at the surface. A relatively large power source must be provided downhole or repeaters used at intervals along the string to boost the signal as it propagates along the drill string.
U.S. Pat. No. 5,163,521 issued Nov. 17, 1992 to Pustanyk et. al., U.S. Pat. No. 5,410,303 issued Apr. 25, 1995 to Comeau et. al., and U.S. Pat. No. 5,602,541 issued Feb. 11, 1997 to Comeau et. al. all describe a telemetry tool, a downhole motor having a bearing assembly and a drilling bit. A sensor and a transmitter are provided in a sealed cavity within the housing of the downhole motor adjacent the drilling bit. A signal from the sensor is transmitted by the transmitter to a receiver in the long haul telemetry tool, which then transmits the information to the surface. The signals are transmitted from the transmitter to the receiver by a wireless system. Specifically, the information is transmitted by frequency modulated acoustic signals indicative of the sensed information. Preferably, the transmitted signals are acoustic signals having a frequency in the range below 5000 Hz.
Further systems have been developed which require the transmission of electromagnetic signals through the surrounding formation. Electromagnetic transmission of the sensed information often involves the use of a toroid positioned adjacent the drilling bit for generation of an electromagnetic wave through the formation. Specifically, a primary winding, carrying the sensed information, is wrapped around the toroid and a secondary winding is formed by the drill string. A receiver may be either connected to the ground at the surface for detecting the electromagnetic wave or may be associated with the drill string at a position uphole from the transmitter.
Generally speaking, as with acoustic and seismic signal transmission, the transmission of electromagnetic signals through the formation typically requires a relatively large amount of power, particularly where the electromagnetic signal must be detectable at the surface. Further, attenuation of the electromagnetic signals as they are propagated through the formation is increased with an increase in the distance over which the signals must be transmitted, an increase in the data transmission rate and an increase in the electrical resistivity of the formation. The conductivity and the heterogeneity of the surrounding formation may particularly adversely affect the propagation of the electromagnetic radiation through the formation. Thus, a relatively large power source is needed downhole to provide the energy required to effect successful telemetry.
Finally, there are typically two methods for creating an electromagnetic antenna downhole. When utilizing a toroid for the transmission of the electromagnetic signal, the outer sheath of the drill string must protect the windings of the toroid while still providing structural integrity to the drill string. This is particularly important given the location of the toroid in the drill string since the toroid is often exposed to large mechanical stresses during the drilling operation and is very bulky. The toroid creates a virtual insulative gap or electrical discontinuity in the drill string thereby allowing an electrical potential bias to be generated. The second method is to mechanically create an electrical discontinuity in the drill string. The electrical discontinuity typically comprises an insulative gap or insulated zone provided in the drill string. Such a mechanism is documented in U.S. Pat. No. 4,691,203 issued Sep. 1, 1987 to Rubin et. al. The insulative gap may be provided by an insulating material comprising a substantial area of the outer sheath or surface of the drill string. For instance, the insulating material may extend for ten to thirty feet along the drill string or only an inch or two. Regardless, the need for the insulative gap to be incorporated into the drill string may interfere with the structural integrity of the drill string resulting in a weakening of the drill string at the gap. Further, the insulating material provided for the insulative gap may be readily damaged during typical drilling operations.
Various attempts have been made in the prior art to address these difficulties or disadvantages associated with electromagnetic transmission systems. However, none of these attempts have provided a fully satisfactory solution as each continues to require the propagation of an electromagnetic signal through the formation. Examples include: U.S. Pat. No. 4,496,174 issued Jan. 29, 1985 to McDonald et. al.; U.S. Pat. No. 4,725,837 issued Feb. 16, 1988 to Rubin; U.S. Pat. No. 4,691,203 issued Sep. 1, 1987 to Rubin et. al.; U.S. Pat. No. 5,160,925 issued Nov. 3, 1992 to Dailey et. al.; PCT International Application PCT/US92/03183 published Oct. 29, 1992 as WO 92/18882; U.S. Pat. No. 5,359,324 issued Oct. 25, 1994 to Clark et. al. and European Patent Specification EP 0 540 425 B1 published Sep. 25, 1996.
Finally, U.S. Pat. No. 6,392,561 issued May 21, 2002 to Davies et. al. provides a short hop telemetry system for transmitting an axial electrical signal embodying information generated from a downhole sensor across the power unit of a downhole motor drilling assembly. However, the configuration of this system requires the sensor to be positioned or located within the housing of the drilling assembly. Thus, this system does not provide for the placement of the sensor in, or the transmission of an axial electrical signal from, a downhole end of a drive train of the drilling assembly below the housing.
Therefore, there remains a need in the industry for a data or power transmission or telemetry system and method for communicating information axially along a drill string. Further, there is a need for a telemetry system and method that communicate or transmit data measurements, sensed information or power through components of the drill string. Still further, there is a need for the downhole telemetry system and method to communicate information and/or power either unidirectionally or bidirectionally axially along or through the drill string.
As well, there is a need for a telemetry system and method that can communicate through components of a drive train comprising the drill string, and preferably, through components of a drill bit assembly comprising the drive train. Finally, the system and method preferably communicate information provided by at least one sensor located in the drive train, and preferably located in the drill bit assembly.